This invention pertains to safeguarded methods and apparatus for providing fluid communication with coiled tubing, useful in communicating fluids within wells, and particularly applicable to drill stem testing and/or operations in sour wells. The invention further pertains to multicentric coiled-in-coiled tubing, useful for safeguarded downhole or conduit operations, and its method of assembly, including preferred and alternate methods. The invention also pertains to the use of coiled-in-coiled tubing with a bottomhole assembly package for operations that may be particularly pertinent to horizontal and/or deviated wells, including operations such as treating or forming or testing or measuring and the like, and in particular, to combinations of the above operations performable in the same run.
This application is related to and comprises a continuation in part of prior pending application having PCT Serial Number PCT/US95/10007. The corresponding U.S. Ser. No. is 08/564/355.
The oil and gas industry uses various methods to test the productivity of wells prior to completing and tying a well into a pipeline or battery. After drilling operations have been completed and a well has been drilled to total depth (xe2x80x9cTDxe2x80x9d), or prior to reaching TD in the case of multi-zoned discoveries, it is common to perform a drill stem test (xe2x80x9cDSTxe2x80x9d). This test estimates future production of oil or gas and can justify a further expenditure of capital to complete the well.
The decision to xe2x80x9ccasexe2x80x9d a well to a particular depth, known as a xe2x80x9ccasing point electionxe2x80x9d, can result in an expenditure in excess of $300,000. Without a DST, a wellsite geologist must make a casing point election based on only core samples, cuttings, well logs, or other indicators of pay thicknesses. In many cases reservoir factors that were not knowable at the time of first penetration of the producing zone, and thus not reflected in the samples, cuttings, etc., can control the ultimate production of a well. A wellsite geologist""s problem is exacerbated if the well is exploratory, or a wildcat well, without the benefit of comparative adjacent well information. Further, the geologist must make a casing point election quickly as rig time is charged by the hour.
A DST comprises, thus, a valuable and commonly used method for determining the productivity of a well so that optimal information is available to the geologist to make a casing point election. Traditionally the DST process involves flowing a well through a length of drill pipe reinserted through the static drilling fluid. The bottom of the pipe will attach to a tool or device with openings through which well fluids can enter. This perforated section is placed across an anticipated producing formation and sealed off from the rest of the wellbore with packers, frequently a pair of packers placed both above and below the formation. The packer placement or packing off technique permits an operator to test only an isolated section or cumulative sections. The testing can involve actual production into surface containers or containment of the production fluid in the closed chamber comprised by the pipe, pressure testing, physically retrieving samples of well fluids from the formation level and/or other valuable measurements.
The native pressure in producing reservoirs is controlled during drilling through the use of a carefully weighted fluid, referred to above and commonly called xe2x80x9cdrilling mudxe2x80x9d. The xe2x80x9cmudxe2x80x9d is continuously circulated during the drilling to remove cuttings and to control the well should a pressurized zone be encountered. The mud is usually circulated down the inside of the drill pipe and up the annulus outside of the pipe and is typically made up using water or oil based liquid. The mud density is controlled through the use of various materials for the purpose of maintaining a desired hydrostatic pressure, usually in excess of the anticipated native reservoir pressure. Polymers and such are typically added to the mud to intentionally create a xe2x80x9cfilter cakexe2x80x9d sheath-like barrier along the wellbore surface in order to staunch loss of over-pressured drilling fluid out into the formation.
As can be easily appreciated, when an upper packer of a DST tool seals an annular area between a test string and a borehole wall, the hydrostatic pressure from the column of drilling fluid is relieved on the wellbore below the packer. The well below the packer, thus, can flow if an open fluid communication channel exists to the surface. At least the well will flow to the extent that native pressure present at the open formation of the isolated section exceeds the hydrostatic head pressure of the tested fluids in the drill pipe. Such produced fluids that flow to or toward the surface are either trapped in the pipe string or collected in a container of known dimensions and/or flared off. By calculating the volume of actual fluid produced, after considering such factors as the time of the test and the size of the choke used, a reasonable estimate of the ultimate potential production capacity of a well can be made. Upon occasion formation pores are too clogged, as by the drilling fluid filter cake, to be overcome by formation pressure and flow. It may be desired in such cases to deliver a gas or an acid to the formation to stimulate flow.
Many wells throughout the world contain hydrogen sulfide gas (H2S), also known as xe2x80x9csour gasxe2x80x9d. Hydrogen sulfide gas can be harmful to humans or livestock at very low concentrations in the atmosphere. In Alberta, Canada, sour wells commonly produce hydrocarbon fluids with concentrations of 2-4% H2S and often as high as 30-35% H2S. These are among the most sour wells in the world. It is also known that sour gas can cause embrittlement of steel, such as the steel used in drill pipe. This is especially true when drill pipe contains hardened steel, which is commonly used to increase the life of the drill string. Due to a tendency for drill pipe to become embrittled when exposed to H2S and the possibly disastrous effect of sour gas in the atmosphere with its potential for environmental damage or injury to people or animals, it is extremely uncommon to perform drill stem tests on sour wells. Even a pin hole leak in a drill pipe used for such purposes could have deleterious results.
Unfortunately, many highly productive wells are very sour and found in exploratory areas. In some cases, oil companies have been prepared to go to the expense of temporarily completing a sour well by renting production tubing and hanging it in a well without cementing casing in place, just to effect a production test. This method, due to the increase in rig time, can cost in excess of $200,000, which could be greater than the cost of a completion in shallow wells.
Coiled tubing is now known to be useful for a myriad of oilfield exploration, testing and/or production related operations. The use of coiled tubing began more than two decades ago. In the years that have followed coiled tubing has evolved to meet exacting standards of performance and to become a reliable component in the oil and gas service industry. Coiled tubing is typically manufactured from strips of low alloy mild steel with a precision cut, and rolled and seam welded in a range of OD (outside diameter) sizes, envisioned to run up to 6 inches. Currently, OD sizes are available up to approximately 4 inches. Improvements in manufacturing technology have resulted in increased material strength and consistent material quality. Development of a xe2x80x9cstrip bias weldxe2x80x9d has improved the reliability of factory made joints in the coiled tubing string. Heat treatment and material changes have increased resistance of the tubing to H2S induced embrittlement and stress corrosion cracking that can incur in operations in sour environments. An increase in wall thickness and the development of higher strength alloys are also allowing the industry to increase the depth and pressure limits within which the tubing may be run. The introduction of new materials and structure, such as titanium and composite material tubing design, is also expected to further expand coiled tubing""s scope of work.
Coiled tubing could be particularly valuable in sour or very sour wells due to coiled tubing""s typically softer steel composition that is not so susceptible to hydrogen sulfide embrittlement. However, another factor inhibits producing sour gas or performing a DST in a sour well with coiled tubing. The repeated coiling and uncoiling of coiled tubing causes tubing walls, presently made of the steel, to plastically deform. Sooner or later the plastic deformation of the tubing wells is likely to cause a fracture. A resulting small pin hole leak or crack could produce emissions.
Oil and gas operations have known the use of concentric pipe strings. Concentric pipe strings provide two non wellbore channels for fluid communication downhole, typically with one channel, such as the inner channel, used to pump fluid (liquid or gas or multiphase fluid) downhole while a second channel, such as the annular channel formed between the concentric strings, used to return fluid to the surface. (A further annulus created between the outer string and the casing or liner or wellbore could, of course, be used for further fluid communication). Which channel is used for which function can be a matter of design choice. Both concentric pipe channels could be used to pump up or down.
Concentric tubing utilizing coiled tubing, at least in part, has been proposed for use in some recent applications. Coiled tubing enjoys certain inherent advantages over jointed pipe, such as greater speed in running in and out of a well, greater flexibility for running in xe2x80x9clivexe2x80x9d wells and greater safety due to requiring less personnel to be present in high risk areas and the absence of joints and their inherent risk of leaks.
Patterson in U.S. Pat. No. 4,744,420 teaches concentric tubing where the inner tubing member may be coiled tubing. It is inserted into an outer tubing member after that member has been lowered into the wellbore. In Patterson the outer tubing member does not comprise coiled tubing. As FIG. 8 of Patterson illustrates, the inner tubing is secured within the outer tubing by spaced apart spoke-like braces or centralizers which hold the tubing members generally centered and coaxial. Sudol in U.S. Pat. No. 5,033,545 and Canadian Patent No. 1325969 discloses coaxially arranged endless inner and outer tubing strings. Sudol""s coaxial composite can be stored on a truckable spool and run in or pulled out of a well by a tubing injector. Sudol""s disclosure does not explicitly disclose how the coaxial tubing strings are maintained coaxial, but Sudol does show an understanding of the use of centralizers. U.S. Pat. No. 5,086,8422 to Cholet discloses an external pipe column 16 which is inserted into a main pipe column comprising a vertical section and a curved section. An internal pipe column is then lowered into the inside of the external pipe column. Cholet teaches that the pipe columns may be formed to be the rigid tubes screwed together or of continuous elements unwound from the surface. Cholet does not teach a single tubing composite that itself is wound on a spool, the composite itself comprising an inner tubing length and an outer tubing length. All of Cholet""s drawings teach coaxial concentricity. U.S. Pat. No. 5,411,105 to Gray teaches drilling with coiled tubing wherein an inner tubing is attached to the reel shaft and extended through the coiled tubing to the drilling tool. Gas is supplied down the inner tube to permit underbalanced drilling. Gray, like Sudol, discloses coaxial tubing. Further, Gray does not teach a size for the inner tube or whether the inner tube comprises coiled tubing. A natural assumption would be, in Gray""s operation, that the inner tube could comprise a small diameter flexible tube insertable by fluid into coiled tubing while on the spool, like wireline is presently inserted into coiled tubing while on the spool. The Griffiths patent, U.S. Pat. No. 5,503,014, issued Apr. 2, 1996, filed Jul. 29, 1994, practices a version of drill stem testing using dual coaxial coil. No test tool or bottomhole assembly is taught.
The present invention solves the problem of providing a safeguarded method for communicating potentially hazardous fluids and materials through coiled tubing. This safeguarded method is particularly applicable for producing and testing fluids from wells including very sour gas wells. The safeguarded method proposes the use of coiled-in-coiled tubing, comprising an inside coiled tubing length located within an outside coiled tubing length. Potentially hazardous fluid or material is communicated through the inside tubing length. The outside tubing length provides a backup protective layer. The outside tubing defines an annular region between the lengths that can be pressurized and/or monitored for a quick indication of any leak in either of the tubing lengths. Upon detection of a leak, fluid communication can be stopped, a well could be killed or shut in, or other measures could be taken before a fluid impermissibly contaminates its surroundings.
As an additional feature, the annular region between the tubing lengths can be used for circulating fluid down and flushing up the inside tubing, for providing stimulating fluid to a formation, for providing lift fluid to the inside tubing or for providing fluid to inflate packers located on an attached downhole device, etc.
The present invention also relates to the assembly of multicentric coiled-in-coiled tubing, the proposed structure offering a configuration and a method of improved or novel design. This improved or novel design provides advantages of efficient, effective assembly, longevity of use or enhanced longevity with use, and possibly enhanced structural strength. A preferred method and alternate methods of assembly of multicentric and concentric coil-in-coil are disclosed.
It has been discovered that coiled-in-coiled tubing can offer the same benefits of flexibility and thrustability that are found in single coiled tubing when compared to jointed pipe, characteristics particularly useful for work in horizontal and/or deviated wells. However, coiled-in-coiled tubing provides the operator with two conduits as opposed to one for the communication of fluids, as from the surface to the bottomhole, or from the bottomhole to the surface, from the surface to tool combinations in a bottomhole assembly, and/or to provide an insulating chamber. These conduits are in addition, of course, to the tubing-wellbore annulus that can or could be used as a conduit.
Some operations, as discussed above and below, can benefit from the availability of a safeguarded or insulated production conduit. Some tools, as mentioned in the above discussion of Sudol and the sand vacuuming tool, prescribe two fluid conduits for their operation, and others might benefit from such.
Given the construction of prototype coiled-in-coiled tubing, it has been subsequently discovered that well operations such as treating, forming, testing and/or measuring operations and the like, and especially including combinations of the above, could be performed cost effectively on coil-in-coil. For instance, the efficiency of testing combined with well enhancing operations could be increased if performed in the same run downhole with other operations. The flexibility provided by the availability of plural conduits for pumping down, pumping up, and circulating fluids, and performing the same simultaneously or sequentially, makes possible many novel combinations of operations not before possible in a run downhole. Plural circulating conduits permit combinations of operations to be performed downhole in new, improved and novel manners. The added efficiency can justify the added cost of utilizing coil-in-coil, as well as add a safety factor.
This invention relates to the use of coiled-in-coiled tubing (several hundred feet of a smaller diameter inner coiled tube located within a larger diameter outer coiled tube) to provide a safeguarded method for fluid communication. The invention is particularly useful for well production and testing. The apparatus and method are of particular practical importance today for drill stem testing and other testing or production in potentially sour or very sour wells. The invention also relates to an improved xe2x80x9cmulticentricxe2x80x9d coiled-in-coiled tubing design, and its method of assembly.
The use of two coiled tubing strings, one arranged inside the other, doubles the mechanical barriers to the outside environment. Fluid in the annulus between the strings can be monitored for leaks. To aid monitoring, the annular region between the coils can be filled with an inert gas, such as nitrogen, or a fluid such as water, mud or a combination thereof, and pressurized.
In one embodiment a fluid, such as water or an inert gas, can be placed in the annulus between the tubings and pressurized. This annular fluid can be pressurized to a greater pressure than either the pressure of the hazardous fluid being communicated via the innermost string or the pressure of the fluid surrounding the outer string, such as static drilling fluid. Because of this pressure differential, if a pin hole leak or a crack were to develop in either coiled tubing string the fluid in the annulus between the inner and outer string would flow outward through the hole. Instead of sour gas, for instance, potentially leaking out and contaminating the environment, the inner string fluid would be invaded by the annular fluid and continue to be contained in a closed system. An annular pressure gauge at the surface could be used to register a pressure drop in annular fluid, indicating the presence of a leak.
Communicated fluids through the inner string could be left in the closed chamber comprised of the inner string, for one embodiment, or could be separately channeled from the coiled-in-coiled tubing at the spool or working reel. Separately channeled fluids could be measured, or fed into a flare at the surface or produced into a closed container, for other embodiments.
The coiled-in-coiled tubing should be coupled or attached to a device at its distal end to control fluids flowing through the inner tube. Fluid communications through the annular channel should also be controlled. At a minimum this control might comprise simply sealing off the annular region. For drill stem testing, packers and packing off techniques could be used in a similar fashion as with standard drill stem tests. An additional benefit is provided by the invention in that a downhole packer could be inflated with fluid supplied down the coiled-in-coiled tubing.
The inner coiled tube is envisioned to vary in size between xc2xdxe2x80x3 (inches) and 5xc2xdxe2x80x3 (inches) in outside diameter (xe2x80x9cODxe2x80x9d). The outer coiled tube can vary between 1xe2x80x3 and 6xe2x80x3 in outside diameter. A preferred size is 1xc2xc to 1xc2xdxe2x80x3 O.D. for the inner tube and 2xe2x80x3 to 2xe2x85x9cxe2x80x3 O.D. for the outer tube.
It is known that steel of a hardness of less than 22 on the Rockwell C hardness scale is suitable for sour gas uses. Coiled tubing can be commonly produced with a hardness of less than 22, being without the need for the strength required for standard drill pipe. Thus, coiled tubing is particularly fit for sour gas uses, including drill stem testing, as disclosed. Other materials such as titanium, corrosion resistant alloy (CRA) or fiber and resin composite could be used for coiled tubing. Alternately, other metals or elements could be added to coiled tubing during its fabrication to increase its life and/or usefulness.
The invention further includes apparatus and method for use in downhole well operations such as treating, forming, testing or measuring and the like, and especially in combinations of the above. Treating operations refer generally to operations such as acidizing or fracturing or heating or other well stimulating activities, including injecting chemical and biological additives. Specifically, treating might refer to operations such as a polymer squeeze to close off suspected water producing zones, clay swelling control mechanisms, sand control mechanisms, filter cake removal systems, iron or sludge control and fines migration control. Treating might also refer to the addition of one or more of the following, either separately or in combination: emulsifiers, gellants, polymers, surfactants, buffers, neutralizers, corrosion control agents, inhibitors, diverting agents, breakers, cements, fluid loss control additives, detergents, cleaning agents, solvents, sequesterants, suspending agents, gels or proppants, foam or defoamers, gases, friction reducers, retarders, lost circulation material, flushes and preflushes, wax or paraffin removers, asphaltine control agents, viscosifiers, dispersants, bonding agents, cement additives and scale inhibitors. Generally, treating fluids could refer to any combination of acid and/or fracturing fluids as well as to additives thereto. Treating fluids would be mixed and applied simultaneously or sequentially according to the need of the particular formation. Treating operations could include jet cleaning and sand vacuuming operations.
Forming operations include operations such as drilling, modifying, perfing (perforating), establishing build sections and forming dog legs, as well as other activities that affect the structure and conformance of the wellbore.
Testing operations include producing operations, including both production testing and long term production. A general purpose tool might be referred to as a production/test tool.
There could be an overlap between testing tools and measuring tools. Measuring tools include the spectrum of logging tools as well as pressure measuring devices, flow meters, densitometers, locating tools, sampling tools and tools to perform chemical analyses or geological and geophysical analyses downhole.
Apparatus for use in well operations in accordance with the present invention comprises coiled-in-coiled tubing having an inner coiled tubing length contained within an outer coiled tubing length. The two tubing lengths define a first inner coil fluid conduit and a second inter-coil xe2x80x9cannularxe2x80x9d fluid conduit. The apparatus includes a bottomhole assembly package adapted to attach to a portion of the coiled-in-coiled tubing, typically attaching to the distal end of the coiled-in-coiled tubing, and in fluid communication with both fluid conduits defined by the coiled-in-coiled tubing.
The apparatus may include at least one packer adapted to be associated with the bottomhole assembly or the tubing. Typically the packer would be associated with the bottomhole assembly and might comprise a straddle packer. The packer optionally could be structured to permit the tubing to reciprocate or to slide while the packer packs off between a portion of the borehole wall and the tubing.
An emergency packer deflation mechanism might be included in the event of loss of communication. The mechanism could operate by pressure application to a sheer pin or a number of pins or by a variety of other methods, which would allow fluid to escape from the packers to the wellbore or to the coil tubing.
In most applications a surface control mechanism would control fluid communication within both the inner conduit and the coiled-in-coiled annular conduit. Preferably the coiled-in-coiled tubing at the surface would be connected to a spool or reel at its proximate end. The flow from both conduits could be separated with an adapting mechanism at the spool or reel to channel or control each flow separately, as desired.
A bottomhole assembly package could range from the elaborate to the simple. A drillstem test tool as disclosed in FIGS. 5 and 5A comprise one bottomhole assembly package. The tool is designed such that it could function as a production/test tool and a treatment injection tool. Valves in the tool control fluid communication between the inner and the annular conduits and the wellbore as well as between the conduits themselves. Alternately, a bottomhole assembly might comprise one or more of a production/test tool, a pump tool, a treatment injection tool, a vacuum tool, a jetting tool, a perfing tool, a drilling tool, an orienting tool, a hydraulic motor and/or an electric motor. A treatment injecting tool could inject treatment fluid. The bottomhole assembly might include a variable spacing unit. Such units could provide spacing from one to fifty meters.
Presently available tools, such as enumerated in the above list, would likely need to be adapted to work effectively with coiled-in-coiled tubing in a bottomhole assembly package. Some tools, such as a Sudol sand vacuuming tool, or a drillstem test tool as in FIG. 5, is adapted to work with coiled-in-coiled tubing. Adapting other tools to function in a bottomhole assembly package connected to coiled-in-coiled tubing may require only an appropriate sub to connect the tool fluid communication ports with the fluid communication capabilities of the coiled-in-coiled tubing, or with the tool sections above. If multiple tools are packaged in a bottomhole assembly, some provision will likely be made to port the tool""s own fluid communication ports with the fluid communication ports of the above tool as well as to port fluid communication through or around the tool in order to serve tools connected below. Such engineering and design parameters can be worked out as preferred bottomhole assembly packages develop. The greater the commercial market for a particular tool package assembly, the greater the likelihood that fluid communication channels will be incorporated into the tool body self as opposed to being arranged in an ad hoc or temporary fashion.
It is envisioned that pumps associated with a bottomhole assembly may include jet pumps, chamber liftpumps, and/or electric pumps. Such pumps could function as alternate systems to recover well effluent to the surface for measurement or analysis. Electrical submersible pumps are known. A wireline will likely extend through one of the two coiled-in-coiled tubing conduits to establish electrical communication between the surface and the bottomhole assembly package. The electrical communication could serve the functions of both power and communication, as is illustrated and taught in U.S. Pat. No. 4,898,236 to Sask, entitled xe2x80x9cDrill Stem Testing System.xe2x80x9d The important role of real time data is discussed in the Sask patent. The wireline could include a conductor within a braided line. Fibre optic wireline cables are also a possibility. If the wireline is to be included in the coiled-in-coiled annular conduit, as opposed to the inner conduit, the coiled-in-coiled tubing would likely be concentric as opposed to multicentric. Any single or multi-line conductor within a braided line or smaller coil tubing could function as a communication cable.
A variety of measuring tools may fortuitously be included in a bottomhole assembly package. Provision would be advantageously provided for multiple pressure, temperature, logging or other measurements.
The apparatus for use in well operations may omit a packer associated with the tubing and/or bottomhole assembly, as the bottomhole assembly package may include multiple tools and function that have no need for packing off. When a packer is included with the bottomhole assembly, one conduit of the coiled-in-coiled tubing could advantageously be used to hydraulically set the packer. Inflatable/deflatable strata packers may be appropriate for many operations.
The availability of the above apparatus, namely coiled-in-coiled tubing and an appropriate bottomhole assembly package, makes possible the performance of a variety of novel, efficient and cost effective downhole well operations, performable in one run. For such operations, the coiled-in-coiled tubing should be connected to the bottomhole assembly package such that both the inner and the annular fluid conduits are in fluid communication with the assembly.
The bottomhole assembly is to be located down a wellbore. Most easily the assembly is injected down the wellbore attached to the distal end of the coiled-in-coiled tubing being injected from a spool. One advantageous method of use of the above apparatus includes packing off between a portion of the wellbore and a portion of the tubing and/or assembly and pumping fluid down at least one of the two coiled-in-coiled tubing conduits for operations. Fluid, for instance, could be pumped down to set the packer. Fluid pumped down the conduit could also be advantageously used to power tools and to circulate into the wellbore. Wellbore fluid could be produced up a conduit, simultaneously or in sequence with pumping down to facilitate flushing operations.
For example, if a combination production/test and treatment injection tool, such as that of FIGS. 5 and 5A, were to comprise the bottomhole assembly, together with a packer, the methodology could include first setting the packer amid the drilling fluid in a wellbore by using water in a first conduit, preferably the annular conduit. The first conduit could then be shut off and wellbore fluid below the packer produced up the second conduit, preferably the inner conduit. The drilling fluid or mud remains in the wellbore tubing annulus above the packer. In the present example subsequent operation will not contaminate or otherwise destroy the value of this drilling fluid by circulating extraneous materials through it.
If testing of the produced fluid indicates that a well treatment might improve production, valves can be opened that permit circulation between the first conduit and the second conduit. Water in the first conduit and production fluid in the second conduit (and in the wellbore beneath the packer to a certain extent) can be circulated out and a treating fluid, such as acid, pumped down. When the fluids are suitably flushed, the second conduit can be closed and the treating fluid, such as acid, injected into the wellbore below the packer through the first conduit. The treating fluid may be followed by water. Both conduits may then be closed while the chemical acts. Production can be reestablished back up the second conduit, producing first any residual fluids in the conduit, spent acid and then formation fluid.
It can be assumed that the acid injected down the first conduit was followed by water such that when the acidizing is complete, water remains trapped in the first conduit. The formation fluid can be advantageously tested anew. If the test results on the produced formation fluid are now satisfactory, the packer can be deflated, particularly aided by using a conduit to depressurize the packer chamber, and the process repeated at another location. If the test results are unsatisfactory, the flush and treatment cycle can be repeated, using the same or different treatment fluids. Straddle packers can be used in lieu of a single packer to suitably isolate a production zone.
If testing indicates that a zone produces water, a polymer squeeze chemical could be applied through one conduit, such as the first conduit, to wall off the zone from production. The success or effectiveness of the polymer squeeze could be immediately subsequently tested by production with the tool. In the above sequence of operations, the drilling fluid in the well above the packer has not been contaminated by the necessity to flush any fluids through the wellbore-tubing annulus above the packer.
A packer might be set downhole such that it permits coiled-in-coiled tubing to slidingly reciprocate while the packer packs off between the wellbore and the tubing wall. Some treating operations such as sand vacuuming and/or jet cleaning require the movement of a tool during operation. Drilling also depends upon movement of the coiled tubing within the wellbore. A packer permitting the tubing to reciprocate through it, set at a build section, might permit, for instance, a horizontal well to be overbalanced in its vertical section, having drilling fluid above the packer, and underbalanced in its horizontal section below the packer. Gas could be pumped down one of the two conduits with liquid down the other, both to the bit, to drill under variably balanced conditions while providing adequate cooling and lifting power to the bit and at the same time a conduit carrying only liquid for acoustic communication and hydraulic fluid.
In one methodology, with or without a packer, fluid could be pumped down both conduits to a bottomhole assembly where each fluid comprises either a hydraulic operating fluid or a well treatment fluid. This methodology would permit the mixing of chemicals downhole. For instance, a first and second chemical might pump more favorably unmixed, such as fracturing fluid and gel setting chemicals and/or gel breaking chemicals, or such as two different acids. It is sometimes advantageous to have two different treatment fluids that are not mixed until ready for use. Heat could be generated downhole more safely by the mixture there of two chemicals.
Combustion downhole might be controlled by a controlled supply of oxygen. Two different tools could be hydraulically operated, each having their own independent hydraulic pressure and flow rate controlled at surface, as a hydraulically operated bit and a hydraulically operated orienting tool, or a hydraulically operated bit and a hydraulic jetting tool. One conduit could contain hydraulic fluid for operating a rotary cleaning jet while the other conduit contained a fluid, such as an acid fluid, for selectively dispensing out the rotating jets. Hydraulic fluid down one conduit could operate a pump while a treating or jetting fluid could be administered through the other conduit. In one embodiment a rotating jet cleaning tool could be operated together with a sand vacuuming tool. Many such tools could be computer controlled through real time feed back data.
In another methodology the outer conduit could be used to provide thermal insulation for fluid in the inner conduit. For example, viscous oil could be produced through the inner conduit while thermal insulation could be provided by a fluid, such as a gas, air, a gel or other insulation material in the outer conduit. For the purposes of the present disclosure a vacuum should be considered as a xe2x80x9cgasxe2x80x9d fluid, as it represents a limiting condition for the presence of a gas. Such insulating fluid could keep the oil temperature up and thus the oil viscosity down so that the oil could be more readily brought to surface.
One utilization of the present invention includes a methodology in which the bottomhole assembly comprises at least a pair of valved producing/treating tools separated by a bottomhole assembly spacer. Wellbore fluid could be produced from two different locations, each up a different conduit. The embodiment could be operated with or without packers. Advantageously the two producing tools could be separated by a packer in order to test alternative producing zones.
A surface computer system could be advantageously employed to recover and analyze data in real-time in order to calculate reservoir parameters. The same surface computer system could be used to control all downhole tool valves for the movement of all fluids and gases. The apparatus and method advantageously includes capability for remote data transmission from the well site to another location.
The present invention also includes optimal methods for assembling coiled-in-coiled tubing. These methodologies include extending a first length of coiled tubing essentially horizontally. A second inner coiled tubing length could then be pumped through the first coiled tubing length and/or pulled through the first coiled tubing length, by means of a cable, and/or injected through the first coiled tubing length by means of a coiled tubing injector. Any combination of pumping, pulling and injecting, together with lubricating between the coils, could be used simultaneously or sequentially to accomplish the assembling of coiled-in-coiled tubing.